Delayed coking plant combined heating and power generation

ABSTRACT

A system includes a heat exchange system and a power generation system. The heat exchange system includes first, second, and third heat exchangers each operable as a continuous source of heat from a delayed coking plant. The first and second heat exchangers heat first and second fluid streams to produce heated first and second fluid streams, respectively. The heated second fluid stream has a lower temperature and a greater quantity of heat than the heated first fluid stream. The third heat exchanger heats a third fluid stream to produce a heated third fluid stream that includes the heated first fluid stream and a hot fluid stream. The heated third fluid stream has a lower temperature than the heated first fluid stream. The power generation system generates power using heat from the heated second and third fluid streams.

CLAIM OF PRIORITY

This application is a continuation of and claims priority to U.S. patentapplication Ser. No. 14/991,706, filed on Jan. 8, 2016, which claimspriority to U.S. Provisional Application Ser. No. 62/209,188, filed onAug. 24, 2015, the entire contents of both of which are incorporatedherein by reference.

BACKGROUND

Delayed coking is a thermal cracking process used in petroleumrefineries to upgrade and convert petroleum residuum, bottoms fromatmospheric and vacuum distillation of crude oil, into liquid and gasproduct streams leaving behind a solid concentrated carbon material,known as petroleum coke. Large amounts of waste heat from delayed cokingplants is often discharged into the environment.

SUMMARY

In a general aspect, a system includes a heat exchange system and apower generation system. The heat exchange system includes a first heatexchanger operable as a continuous source of heat from a delayed cokingplant, the first heat exchanger configured to heat a first fluid streamto produce a heated first fluid stream. The heat exchange systemincludes a second heat exchanger operable as a continuous source of heatfrom the delayed coking plant, the second heat exchanger configured toheat a second fluid stream to produce a heated second fluid stream. Theheated second fluid stream has a lower temperature and a greaterquantity of heat than the heated first fluid stream. The heat exchangesystem includes a third heat exchanger operable as a continuous sourceof heat to the delayed coking plant, the third heat exchanger configuredto heat a third fluid stream to produce a heated third fluid stream. Thethird fluid stream includes the heated first fluid stream and a hotfluid stream. The heated third fluid stream has a lower temperature thanthe heated first fluid stream. The power generation system is configuredto generate power using heat from the heated second fluid stream and theheated third fluid stream.

Aspects can include one or more of the following features.

The system includes a fluid storage tank configured to pass the hotfluid stream continuously. The fluid storage tank is configured toreceive an intermittent hot stream. The system includes a fourth heatexchanger operable as an intermittent source of heat from the delayedcoking plant. The fourth heat exchanger is configured to heat a fourthfluid stream to produce the intermittent hot stream. The intermittenthot stream has a greater quantity of heat than the heated first fluidstream. The intermittent hot stream has a lower temperature than theheated first fluid stream. The fourth heat exchanger recovers heat froman output stream from a coker blowdown tower in the delayed cokingplant. The output stream is an intermittent heat source. The outputstream includes an overhead stream from the coker blowdown tower. Theoutput stream includes a bottom stream from the coker blowdown tower.The heat exchange system includes multiple fourth heat exchangers eachconfigured to heat a portion of the intermittent fluid stream. Eachfourth heat exchanger recovers heat from a corresponding intermittentheat source in the delayed coking plant.

The first heat exchanger recovers heat from a continuous heat source inthe delayed coking plant, the continuous heat source having atemperature of at least about 134° C.

The first heat exchanger recovers heat from a bottom stream from adebutanizer in the delayed coking plant. The bottom stream from thedebutanizer includes a stabilized naphtha stream.

The first heat exchanger recovers heat from a sponge oil stream from afractionator in the delayed coking plant.

The first heat exchanger recovers heat from a light coked gas oilproduct stream from a fractionator in the delayed coking plant.

The first heat exchanger recovers heat from a heavy cracked gas oilproduct stream from a fractionator in the delayed coking plant.

The heat exchange system includes multiple first heat exchangers eachconfigured to heat a portion of the first fluid stream. Each first heatexchanger recovers heat from a corresponding continuous heat source inthe delayed coking plant.

The second heat exchanger recovers heat from a continuous heat source inthe delayed coking plant, the continuous heat source having atemperature of less than about 134° C.

The second heat exchanger recovers heat from an overhead stream from afractionator in the delayed coking plant.

The second heat exchanger recovers heat from an inter-stage stream of acoker gas compressor in the delayed coking plant.

The second heat exchanger recovers heat from a discharge stream from acoker gas compressor in the delayed coking plant.

The heat exchange system includes multiple second heat exchangers eachconfigured to heat a portion of the second fluid stream. Each secondheat exchanger recovers heat from a corresponding continuous heat sourcein the delayed coking plant.

The temperature of the heated third fluid stream is less than thetemperature of the third fluid stream.

The third heat exchanger is configured to heat a stripper bottom productfrom a stripper in the delayed coking plant by exchange with the thirdfluid stream.

The third heat exchanger is configured to provide heat to re-boil thestripper bottom product prior to the stripper bottom product beingreturned to the stripper.

The third heat exchanger is configured to heat a rich sponge oil streamfrom a sponge absorber in the delayed coking plant by exchange with thethird oil stream.

The third heat exchanger is configured to heat the rich sponge oilstream between the sponge absorber and a fractionator in the delayedcoking plant.

The heat exchange system includes multiple third heat exchangers eachconfigured to heat a corresponding stream in the delayed coking plant byexchange with a portion of the third fluid stream.

The system includes a coker heat exchanger configured to heat a feedstream into a coker heater by exchange with a pumparound stream.

The power generation system includes an Organic Rankine cycle system.

The power generation system is configured to generate at least about 9MW of power.

Heat from the heated second fluid stream and the heated third fluidstream is used to heat iso-butane in the power generation system. Poweris generated from expansion of iso-butane vapor in the power generationsystem.

The system includes an accumulation tank. The first fluid stream, thesecond fluid stream, or both includes fluid from the accumulation tank.The accumulation tank is configured to receive the heated second fluidstream and the heated third fluid stream from the power generationsystem.

One or more of the first fluid stream, the second fluid stream, or thethird fluid stream includes an oil stream.

The system is integrated into the delayed coking plant as a retrofit tothe delayed coking plant. One or more existing heat exchangers in thedelayed coking plant are no longer used following the retrofit.Following the retrofit, the delayed coking plant uses up to about 13%less in heating utility consumption.

In an aspect, a method includes heating a first fluid stream to producea heated first fluid stream by exchange with a first continuous sourceof heat from a delayed coking plant. The method includes heating asecond fluid stream to produce a heated second fluid stream by exchangewith a second continuous source of heat from the delayed coking plant.The heated second fluid stream has a lower temperature and a greaterquantity of heat than the heated first fluid stream. The method includesheating a stream in the delayed coking plant by exchange with a thirdfluid stream to produce a heated third fluid stream. The third fluidstream includes the heated first fluid stream and a hot fluid stream.The heated third fluid stream has a lower temperature than the heatedfirst fluid stream. The method includes generating power using heat fromthe heated second fluid stream and the heated third fluid stream.

Aspects can include one or more of the following features.

The method includes continuously passing the hot fluid stream from afluid storage tank. The method includes receiving an intermittent hotstream at the fluid storage tank. The method includes heating a fourthfluid stream to produce the intermittent hot stream by exchange with anintermittent source of heat from the delayed coking plant. Theintermittent hot stream has a greater quantity of heat than the heatedfirst fluid stream. The intermittent hot stream has a lower temperaturethan the heated first fluid stream. Heating the fourth fluid streamincludes heating the third fluid stream using heat recovered from anoutput stream from a coker blowdown tower in the delayed coking plant.The output stream includes a stripper bottom product from a stripper inthe delayed coking plant by exchange with the fourth fluid stream. Theoutput stream includes a rich sponge oil stream from a sponge absorberin the delayed coking plant by exchange with the fourth fluid stream.

Heating the first fluid stream includes heating the first fluid streamusing heat recovered from a bottom stream from a debutanizer in thedelayed coking plant.

Heating the first fluid stream includes heating the first fluid streamusing heat recovered a sponge oil stream from a fractionator in thedelayed coking plant.

Heating the first fluid stream includes heating the first fluid streamusing heat recovered from a light coked gas oil product stream from afractionator in the delayed coking plant.

Heating the first fluid stream includes heating the first fluid streamusing heat recovered from a heavy cracked gas oil product stream from afractionator in the delayed coking plant.

Heating the second fluid stream includes heating the second fluid streamusing heat recovered from an overhead stream from a fractionator in thedelayed coking plant.

Heating the second fluid stream includes heating the second fluid streamusing heat recovered from an inter-stage stream and by exchange with adischarge stream of a coker gas compressor in the delayed coking plant.

Heating a stream in the delayed coking plant includes heating a stripperbottom product from a stripper in the delayed coking plant.

Heating a stream in the delayed coking plant includes heating a richsponge oil stream from a sponge absorber in the delayed coking plant.

The method includes heating a feed stream into a coker heater in thedelayed coking plant by exchange with a fluid pumparound stream.

Generating power includes generating power using an Organic Rankinecycle system.

Generating power includes generating at least about 9 MW of power.

Generating power includes heating iso-butane using heat from the heatedsecond fluid stream and the heated fourth fluid stream and expandingiso-butane vapor to generate power.

The method includes returning the heated second fluid stream and theheated third fluid stream to an accumulation tank.

One or more of the first fluid stream, the second fluid stream, or thethird fluid stream includes an oil stream.

The systems and methods described here can have one or more of thefollowing advantages. The combined heat and power system described hereis a combination of heat exchange components, heat storage components,and heat-to-power conversion components that can be integrated into adelayed coking plant to enable more efficient operation of the delayedcoking plant. The number of heat exchangers used in the delayed cokingplant can be reduced by feeding recovered waste heat back into thedelayed coking plant using networks of heat exchangers in the combinedheat and power system. The recovered waste heat can be used for heatingand cooling in the delayed coking plant, thus enabling a reduction inconsumption of heating or cooling utilities by the delayed coking plant.Waste heat and greenhouse gases released into the environment can bereduced by the recovery and reuse of waste heat by the combined heat andpower system.

The combined heat and power system described here can enable carbon-freepower generation using waste heat recovered from the delayed cokingplant. For instance, up to about 9 MW of power can be generated usingrecovered waste heat.

The combined heat and power system described can be integrated into anexisting delayed coking plant as a retrofit or can be integrated into anewly constructed delayed coking plant. A retrofit to an existingdelayed coking plant allows the efficiency and power generationadvantages offered by the combined heat and power system to beaccessible with a low-capital investment. The combined heat and powersystem can make use of existing structure in a delayed coking plantwhile still enabling efficient waste heat recovery and conversion ofwaste heat to power. The integration of a combined heat and power systeminto an existing delayed coking plant can be generalizable toplant-specific operating modes.

Other features and advantages are apparent from the followingdescription and from the claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of a combined heat and power system.

FIG. 2 is a diagram of a retrofit of a fractionation section of adelayed coking plant.

FIG. 3 is a diagram of a retrofit of a coking section of a delayedcoking plant.

FIG. 4 is a diagram of a retrofit of a blowdown section of a delayedcoking plant.

FIG. 5 is a diagram of a retrofit of an overhead gas compression systemof a delayed coking plant.

FIG. 6 is a diagram of a retrofit of an absorber-stripper section of adelayed coking plant.

FIG. 7 is a diagram of a retrofit of a sponge absorber section of adelayed coking plant.

FIG. 8 is a diagram of a retrofit of a steam generation section of adelayed coking plant.

FIG. 9 is a diagram of a retrofit of a rundown cooler section of adelayed coking plant.

FIG. 10 is a flow chart.

FIG. 11 is a diagram of a grassroots fractionation section of a delayedcoking plant.

FIG. 12 is a diagram of a grassroots coking section of a delayed cokingplant.

FIG. 13 is a diagram of a grassroots blowdown section of a delayedcoking plant.

FIG. 14 is a diagram of a grassroots overhead gas compression system ofa delayed coking plant.

FIG. 15 is a diagram of a grassroots absorber-stripper section of adelayed coking plant.

FIG. 16 is a diagram of a grassroots sponge absorber section of adelayed coking plant.

FIG. 17 is a diagram of a grassroots rundown cooler section of a delayedcoking plant.

DETAILED DESCRIPTION

We describe here a combined heat and power generation system for usewith a delayed coking plant. Networks of heat exchangers recover bothhigh-grade and low-grade waste heat from the delayed coking plant. Therecovered waste heat is fed back into the delayed coking plant forintra-plant heating and cooling, thus saving energy that would otherwisehave been used for heating and cooling within the delayed coking plantand allowing the delayed coking plant to operate more efficiently. Forinstance, the combined heat and power generation system can reduce theconsumption of heating utilities by up to about 13% (about 85 MM Btu/h).The recovered waste heat is also used to power a power generation systemsuch as an Organic Rankine cycle system, enabling the generation of upto about 9 MW of carbon-free power. The combined heat and powergeneration system described here can be implemented as a retrofit to anexisting delayed coking plant and thus is accessible as a low-capital,energy-saving investment that is compatible with existing structures.The combined heat and power generation system can also be integratedinto a newly constructed delayed coking plant.

Delayed coking is a thermal cracking process used in petroleumrefineries to upgrade and convert petroleum residuum, bottoms fromatmospheric and vacuum distillation of crude oil, into liquid and gasproduct streams. Delayed coking leaves behind a solid, concentratedcarbon material known as petroleum coke. Delayed coking can producethree physical structures of petroleum coke: shot coke, sponge coke, andneedle coke. Depending on the physical structure and chemical propertiesof the petroleum coke, the coke can be burned as a fuel, calcined foruse, for example, in aluminum or steel industrial applications, orgasified to produce syngas, steam, H₂, or power.

A network of heat exchangers incorporated into a delayed coking plantcan recover both high-grade and low-grade waste heat from the delayedcoking plant. Low-grade waste heat is waste heat that is below, forinstance, 134° C.; high grade waste heat is waste heat that is above,for instance, 134° C. The waste heat recovered by the network of heatexchangers is fed back into the delayed coking plant for intra-plantheating and cooling, thus saving energy that would otherwise have beenused for intra-plant heating and cooling. For instance, using waste heatfor intra-plant heating and cooling can help to reduce the fuelconsumption of a coker furnace or reduce the consumption of mediumpressure steam by the delayed coking plant or both, thus enabling moreefficient operation of the delayed coking plant. The waste heat is alsoused to power a power generation system, for example, a carbon-freepower generation system such as an Organic Rankine cycle (ORC) system.Power generated by the power generation system can be used locally (forexample, at the delayed coking plant) or exported to an electricitygrid. The network of heat exchangers can be implemented as a retrofit toan existing delayed coking plant or can be included in a newlyconstructed delayed coking plant (sometimes referred to as a grassrootsdelayed coking plant).

Referring to FIG. 1, in a combined heat and power system 10, networks ofheat exchangers recover both high-grade and low-grade waste heat from adelayed coking plant. In the combined heat and power system 10, aheating fluid stream 18, such as a stream of oil, water, an organicfluid, or another fluid, recovers heat from several continuous andintermittent sources of waste heat in the delayed coking plant byexchange via exchangers 1-9. Portions of heating fluid stream 18, heatedby exchange with sources of waste heat in the delayed coking plant, canbe used for intra-plant heating within the delayed coking plant. Aheating fluid stream 40, heated by exchange with sources of waste heatin the delayed coking plant, is provided to power generation system 50to act as a heat source for power generation.

In operation, heating fluid stream 18 is flowed through the heatexchangers 1-9. An inlet temperature of the heating fluid that is flowedinto the inlets of each of heat exchangers 1-9 is substantially thesame, for example, 50° C. Each heat exchanger 1-9 heats the heatingfluid to a respective temperature that is greater than the inlettemperature. The heated heating fluids from heat exchangers 1-9 arecombined and flowed through power generation system 50. Heat from theheated heating fluid heats the working fluid of the ORC therebyincreasing the working fluid pressure and temperature. The heat exchangewith the working fluid results in a decrease in the temperature of theheating fluid. The heating fluid is then collected in an accumulationtank 20 and can be pumped back through heat exchangers 1-9 to restartthe waste heat recovery cycle.

The heating fluid circuit to flow heating fluid through heat exchangers1-9 can include multiple valves that can be operated manually orautomatically. For example, the delayed coking plant can be fitted withthe heating fluid flow pipes and valves. An operator can manually openeach valve in the circuit to cause the heating fluid to flow through thecircuit. To cease waste heat recovery, for example, to perform repair ormaintenance or for other reasons, the operator can manually close eachvalve in the circuit. Alternatively, a control system, for example, acomputer-controlled control system, can be connected to each valve inthe circuit. The control system can automatically control the valvesbased, for example, on feedback from sensors (for example, temperature,pressure or other sensors), installed at different locations in thecircuit. The control system can also be operated by an operator.

Heating fluid is stored in an accumulation tank 20 at, for example, 50°C., and leaves accumulation tank 20 as heating fluid stream 18. A firstportion 22 of heating fluid stream 18 feeds a first sub-network 60 ofheat exchangers 4, 5, 6, 7 (sometimes referred to as sub-network A) thatrecover high-grade waste heat from continuous sources of high-grade heatin the delayed coking plant. A second portion 24 of heating fluid stream18 feeds a second sub-network 70 of heat exchangers 1, 2, 3 (sometimesreferred to as a sub-network B) that recover low-grade waste heat fromcontinuous sources of low-grade heat in the delayed coking plant. Athird portion 26 of heating fluid stream 18 feeds a third sub-network 80of heat exchangers 8, 9 (sometimes referred to as sub-network C) thatrecover waste heat from intermittent sources of heat in the delayedcoking plant.

In sub-network A 60, a heating fluid sub-stream 22 a recovers waste heatfrom a stabilized naphtha stream 612 from the bottom of a debutanizer605 via heat exchanger 4 in an absorber-stripper section 500, 580 of thedelayed coking plant (see, for example, FIGS. 6 and 15). A heating fluidsub-stream 22 b recovers waste heat from lean sponge oil 118 via heatexchanger 5 in a sponge absorber section 600, 680 of the delayed cokingplant (see, for example, FIGS. 7 and 16). A heating fluid sub-stream 22c recovers waste heat from a light coked gas oil (LCGO) product 132 viaheat exchanger 6 in a rundown cooler section 800, 880 of the delayedcoking plant (see, for example, FIGS. 9 and 17). A heating fluidsub-stream 22 d recovers waste heat from a heavy cracked gas oil (HCGO)product 704 (see, for example, FIGS. 9 and 17) via heat exchanger 7 inthe rundown cooler section 800, 880. Heating fluid sub-streams 22 a, 22b, 22 c, 22 d are combined into a heating fluid header 30.

In sub-network B 70, a heating fluid sub-stream 24 a recovers waste heatfrom a fractionator overhead stream 140 via heat exchanger 1 in afractionation section 100, 180 of the delayed coking plant (see, forexample, FIGS. 2 and 11). A heating fluid sub-stream 24 b recovers wasteheat from a compressor inter-stage stream 408 via heat exchanger 2 in anoverhead gas compression system 400, 480 of the delayed coking plant(see, for example, FIGS. 5 and 14). A heating fluid sub-stream 24 crecovers waste heat from a compressor discharge stream 416 via heatexchanger 3 in the overhead gas compression system 400, 480. Heatingfluid sub-streams 24 a, 24 b, 24 c are combined into a heating fluidheader 28.

In sub-network C 80, heat exchangers 8 and 9 enable waste heat to berecovered from intermittent hot sources in a blowdown section 300, 380(see, for example, FIGS. 4 and 13). A heating fluid sub-stream 26 arecovers waste heat from a coker blowdown tower overhead stream 314 viaheat exchanger 8. A heating fluid sub-stream 26 b recovers waste heatfrom a coker blowdown tower bottom stream 312 via heat exchanger 9.Heating fluid sub-streams 26 a, 26 b heated from the intermittent hotsources are combined into an intermittent header 32 with a temperatureof, for example, about 180° C.

Because of the intermittent nature of heat exchangers 8, 9, there can betimes during the operation of combined heat and power system 10 in whichneither heat exchanger 8, 9 is operating, times in which only one ofheat exchangers 8, 9 is operating, and times in which both heatexchangers 8, 9 are operating. In some cases, the operations of heatexchanger 8 and heat exchanger 9 at least partially overlap such thatboth heat exchangers 8, 9 are operating at the same time. When neitherheat exchanger 8, 9 is operating, the flow of third portion 26 ofheating fluid stream 18 can be halted. When both heat exchangers 8, 9are operating, the flow of third portion 26 of heating fluid stream 18can be at a maximum level. When only one heat exchanger 8, 9 isoperating, the flow of third portion 26 of heating fluid stream 18 canbe at a level less than the maximum level.

Heating fluid from intermittent header 32 is stored in a thermal storagetank 34, for example, an insulated tank with a one-day capacity. Thermalstorage tank 34 can use hot oil, molten salt, or another medium forthermal storage. Thermal storage tank 34 collects the intermittent wasteheat from intermittent header 32 and continuously or periodicallydischarges a heating fluid stream 36, for example, on an hourly basis orat another interval. In some cases, multiple thermal storage tanks 34can be used, such as two thermal storage tanks 34. One of the thermalstorage tanks 34 can be discharging heating fluid into heating fluidstream 36 while the other of the thermal storage tanks 34 is receivingheating fluid from intermittent header 32. The temperature of theheating fluid from intermittent header 32 flowing into thermal storagetank 34 is greater than or equal to the temperature of heating fluidstream 36 discharged from thermal storage tank 34, assuming little to noheat loss and a well-insulated thermal storage tank. In an example, thetemperature of heating fluid stream 36 can be about 180° C., such as180.8° C., and the temperature of intermittent header 34 can be equal toor greater than about 180° C.

Heating fluid stream 36 from thermal storage tank 34 is joined withheating fluid header 30 from sub-network A to form heating fluid stream38. In some cases, the volume of heating fluid stream 36 can be smallerthan the volume of heating fluid header 30. For instance, heating fluidstream 36 can be less than about 50% of the FCp of heating fluid header30. Heating fluid stream 38 is used for intra-plant heating in thedelayed coking plant. Heat exchanger 11 heats a stripper bottom product514 (see, for example, FIGS. 6 and 15) for re-boiling of the stripperbottom using heat from heating fluid stream 38. Heating stripper bottomproduct 514 using heat from heating fluid stream 38 allows the role of amedium pressure steam (MPS) re-boiler 526 to be reduced or eliminated,thus enabling conservation of medium pressure steam in the delayedcoking plant. Heat exchanger 12 heats rich sponge oil 136 from a spongeabsorber 606 (see, for example, FIGS. 7 and 16) using heat from heatingfluid stream 38. Exchange at heat exchangers 11, 12 cools heating fluidstream 38 slightly.

Example thermal loads of the heat exchangers 1-12 in the examplecombined heat and power system 10 are shown in Table 1. Table 1 alsoshows the temperature of the heating fluid entering each heat exchangerand the temperature of the heating fluid exiting each heat exchanger(for example, following exchange with a stream in the delayed cokingplant).

TABLE 1 Heat exchanger thermal loads and heating fluid temperatures.Heat Thermal load Entry temp. Exit temp. exchanger (Gcal/h) (° C.) (°C.) 1 55.7 50 114 2 10.1 50 91 3 4.5 50 72 4 30.45 50 194 5 11.14 50 1946 13.76 50 181 7 7.80 50 202 8 63.3 50 174 9 10.1 50 235 11 21.8 188.9155.9 12 5.74 155.9 146.7

Heating fluid stream 38 is joined with heating fluid header 28 fromsub-network B to form heating fluid stream 40. Heating fluid stream 40leaves the networks of heat exchangers and enters power generationsystem 50, such as an ORC system. An ORC system is an energy conversionsystem that uses a flow of an organic fluid, such as refrigerants orhydrocarbons (for example, iso-butane liquid), for power generation.Other types of power generation systems can be used in place of an ORCsystem in the combined heat and power system 10. Power generation system50 is powered in part by waste heat recovered from the delayed cokingplant by the heating fluid sub-streams described above. This use ofrecovered waste heat enables efficient, carbon-free power generation bypower generation system 50.

The total heat load for heat exchangers 4-7 in sub-network A is, forexample, about 63.15 Gcal/h and the temperature of heating fluid header30 exiting sub-network A is, for example, about 191.2° C. The total heatload for heat exchangers 1-3 in sub-network B can be, for example, 70.3Gcal/h (higher than that of sub-network A) and the temperature ofheating fluid header 28 exiting sub-network B is, for example, about103.2° C. (lower than that of sub-network A). The total heat load forheat exchangers 8 and 9 is, for example, about 73.4 Gcal/h (higher thanthat of sub-network A) and the temperature of intermittent header 32 is,for example, about 180° C. (lower than that of sub-network A). In thisconfiguration, heating fluid header 30 has a higher temperature but alower quantity of heat than both heating fluid header 28 andintermittent header 32. This configuration can have advantages, forexample, in enabling efficient heat transfer between high temperatureheating fluid stream 38 and stripper bottoms and rich sponge oil at heatexchangers 11, 12.

In power generation system 50, iso-butane liquid 51 (for example, 385kg/s) at about 4 bar and 29° C., is pumped by a pump 52 to 9.5 bar andfed into an evaporator 56. Evaporator 56 evaporates iso-butane liquid 51using heat from heating fluid stream 40. The evaporated iso-butane is asaturated gas. In some cases, the available quality of heat in thedelayed coking plant does not allow huge superheating of the evaporatediso-butane gas. The iso-butane ORC phase envelope has positive slope andthe expansion of iso-butane in a turbine 56 can be in the superheatingregion. In some cases, additional superheating of the iso-butane in aheat exchanger positioned after the evaporator can be valuable for powergeneration. For instance, the heat exchanger can use heat recovered froma waste heat stream in the delayed coking plant, such as heat from lowpressure steam going to air coolers in the delayed coking plant.

The evaporated iso-butane, heated to 62° C. by evaporator 56, isexpanded in a turbine 54 to generate power, for example, 9.8 MW ofpower. The vapor-phase iso-butane from turbine 54 is condensed into aliquid phase in a condenser 58 from 52° C. to 29° C. by heat exchangewith water 59 at 20° C. The condensed liquid iso-butane returns to pump52.

Following exchange with iso-butane 51 in evaporator 56, heating fluidstream 40 is cooled, for example, to 50° C. The cooled heating fluidstream 40 returns to accumulation tank 20. In some examples, an aircooler 42 can be used to further cool heating fluid stream 40 prior tostorage in accumulation tank 20, for example, to allow for management ofabnormal situations, such as to close the heat balance of combined heatand power system 10 in the event of a disturbance.

Integrating combined heat and power system 10 into a delayed cokingplant, either as a retrofit or as part of a grassroots plant, can enablemore efficient operation of the delayed coking plant. The number of heatexchangers used in the delayed coking plant can be reduced by feedingrecovered waste heat back into the delayed coking plant using thenetworks of heat exchangers that form part of combined heat and powersystem 10. The amount of waste heat and greenhouse gases released intothe environment can be reduced accordingly, and thus the delayed cokingplant can operate more efficiently. In some examples, a reduction of upto about 13% (for example, at least about 21.5 Gcal/h or at least about85 MM Btu/h) in consumption of heating utilities by the delayed cokingplant can be achieved by implementing the networks of heat exchangers ofcombined heat and power system 10. Furthermore, integrating combinedheat and power system 10 into a delayed coking plant enables carbon-freepower generation using recovered waste heat from the delayed cokingplant. For instance, up to about 9 MW of power can be generated usingrecovered waste heat from the delayed coking plant.

Combined heat and power system 10 can be integrated into an existingdelayed coking plant as a retrofit or can be integrated into a newlyconstructed delayed coking plant. A retrofit to an existing delayedcoking plant allows the efficiency and power generation advantagesoffered by combined heat and power system 10 to be accessible with alow-capital investment. Combined heat and power system 10 can make useof existing structure in a delayed coking plant while still enablingwaste heat recovery and conversion of waste heat to power. Theintegration of combined heat and power system 10 into an existingdelayed coking plant can be generalizable to plant-specific operatingmodes.

Sections of a retrofit to a delayed coking plant are depicted in FIGS.2-9. In FIGS. 2-9, temperatures and thermal duties are shown as boxed orcircled numbers, respectively.

FIG. 3 shows a coking section 200 of a delayed coking plant that hasbeen retrofit to incorporate the network of heat exchangers describedsupra. Coking section 200 includes one or more pairs of coke drums 204,in which a vapor-liquid mixture that makes up a feed stream 210 intocoke drums 204 is converted into petroleum coke 207 and lighthydrocarbon vapors 206 (sometimes referred to as overhead vapors 206).In the example of FIG. 2, coking section 200 includes two coke drums 204a, 204 b. In some examples, coking section 200 can include two pairs ofcoke drums 204, three pairs of coke drums 204, or more than three pairsof coke drums 204.

Coking section 200 operates as a batch-continuous process. Feed stream210 is a continuous flow that is switched between the two coke drums 204a, 204 b by a switch valve 205. Switch valve 205 is connected to eachcoke drum 204 a, 204 b via an insulated transfer line 211 a, 211 b,respectively. In some examples, switch valve 205 is a three-way valvewith a port to each coke drum 204 a, 204 b and a port to a recirculationline that returns to a fractionator 102 (FIG. 1), for use during startupand shutdown of the coking section. While one coke drum (for example,coke drum 204 a) is online for coking and receiving feed stream 210, theother coke drum (for example, coke drum 204 b) is offline for de-coking.Periodically, coke drum 204 a is switched offline for de-coking and cokedrum 204 b is switched online to receive feed stream 210.

Feed stream 210 is received from the bottom of fractionator 102 (FIG.2). In some examples, feed stream 210 is received in coking section 200at a temperature that is too low for coke formation. Feed stream 210 canbe pumped by a heater charge pump (not shown) through a coker heater 202prior to being fed into coke drum 204. Coker heater 202 rapidly heatsfeed stream 210 to a temperature appropriate for coke formation in thecoke drum. For instance, coke heater 202 can heat feed stream 210 to athermal cracking temperature of between about 480° C. and about 510° C.In some examples, steam can be injected into the heater coils of cokerheater 202 in order to maintain a target minimum velocity and residencetime of feed stream 210 in coker heater 202, thus suppressing theformation of coke in coker heater 202.

Referring also to FIG. 2, overhead vapors 206 from coke drums 204 arefed into a fractionator 102 in a retrofit fractionation section 100 ofthe delayed coking plant. Overhead vapors 206 enter below a shed sectionof fractionator 102. A circulating heavy cracked gas oil (HCGO)pumparound stream 90 from a pumparound pan of a debutanizer 605re-boiler (FIG. 7) is pumped into a tray wash section of fractionator102, which is above the shed section. HCGO pumparound stream 90 is usedto remove heat from fractionator 102, thus condensing heavy gas oil andcooling the vapors that ascend through fractionator 102. For instance,HCGO pumparound stream 90 quenches and washes overhead vapors 206,cleaning and cooling the vapors and condensing a recycle stream. Therecycle stream exits the bottom of fractionator 102 as a portion of feedstream 210 that is fed into coker section 200. For instance, feed stream210 can be pumped by a heater charge pump (not shown) through cokerheater 202 (FIG. 3). Feed stream 210 can also include condensed recycledcrude 103 that is fed into the bottom of fractionator 102. Recycledcrude 103 can include hot vacuum reduced crude from a vacuumdistillation unit. Recycled crude 103 can include cold crude, forexample, from a tank storage, that is preheated by a heat exchanger 105,by a heat exchanger 107, or by both heat exchangers 105, 107 prior toentering the bottom of fractionator 102. The bottom of fractionator 102can act as a reservoir that provides surge capacity for excess recycledcrude 103 or excess overhead vapors 206 from coking section 200.

HCGO pumparound stream 90 is withdrawn from fractionator 102 and flowsthrough heat exchanger 13, where feed stream 210 is heated withrecovered waste heat from HCGO pumparound stream 90. The heating of feedstream 210 at heat exchanger 13 enables feed stream 210 to enter cokerheater 202 at a higher temperature than it would have prior to theretrofit (for example, about 300° C. in the retrofit versus a lowertemperature, such as about 280° C. prior to the retrofit). The highertemperature of feed stream 210 thus enables fuel savings in coker heater202 and allows coker heater 202 to have a lower thermal load (forexample, 149.9 Gcal/h in the retrofit versus 162.6 Gcal/h prior to theretrofit).

After waste heat from HCGO pumparound stream 90 is recovered at heatexchanger 13, HCGO pumparound stream 90 can be used to preheat recycledcrude 103 via heat exchanger 107. HCGO pumparound stream can also beused to reboil debutanizer 605 (FIG. 7) via a heat exchanger 618.

Prior to the retrofit of the delayed coking plant, HCGO pumparoundstream 90 was in some cases used to contribute to the generation ofmedium pressure steam (MPS) 702 from boiler feed water (BFW) 725 via aheat exchanger 712 in a steam generation section 700 (FIG. 8) of thedelayed coking plant. In the retrofit delayed coking plant, heatexchanger 712 is not used for steam generation and HCGO pumparoundstream can bypass steam generation section 700. In some examples, steamcan be generated in a convection section of coker heater 202. A commonsteam drum can be used, and circulation through a steam-generating coilof coker heater 202 can be provided by a boiler feed water circulatingpump.

The washed, cooled vapors in fractionator 102 pass through a rectifyingsection of fractionator 102, where the vapors are separated into gases,gasoline, diesel, HCGO, and recycle. In some examples, an oversizedfractionator can be used to increase or maximize the amount of dieselproduct and to reduce or minimize the amount of HCGO sent to otherrefinery plants (for example, fluid catalytic cracking).

HCGO product 120 exiting fractionator 102 can be stripped by an HCGOstripper 124 to remove light ends 128, which are returned tofractionator 102. The remaining HCGO product 126 can be partially cooledthrough exchange with recycled crude 103 via heat exchanger 105. In somecases, HCGO product can be filtered, for instance by a backwash filter.Referring to FIG. 8, a portion 706 of HCGO product 126 can be furthercooled in steam generation section 700 via a heat exchanger 710,contributing to the generation of medium pressure steam 702 from BFW725, and directed to a seal oil filter.

Referring also to FIG. 9, a portion 704 of HCGO product 126 is processedin rundown cooler section 800. A first portion 705 passes through heatexchanger 7, which recovers waste heat from the HCGO product 704 anduses the recovered waste heat to heat heating fluid sub-stream 22 d. TheHCGO product 704 is cooled to storage temperature (for example, 90° C.)and sent to a storage. With the presence of heat exchanger 7, an aircooler 802 used to cool HCGO product 704 prior to the retrofit is nolonger used except, for example, for management of abnormal situations.A second portion 707 of HCGO product is sent to other units of thedelayed coking plant.

Referring again to FIG. 2, light coked gas oil (LCGO) product 122exiting fractionator 102 can be stripped by an LCGO stripper 130 toremove light ends 134, which are returned to fractionator 102. Theremaining LCGO product 132 can be partially cooled through exchange withrecycled crude via a heat exchanger (not shown). Referring to FIG. 9,LCGO product 132 can be pumped to rundown cooler section 800, whereheating fluid sub-stream 22 c is heated in heat exchanger 6 withrecovered waste heat from LCGO product 132. A portion 808 of the cooledLCGO product 132 is sent to a flushing oil coalescer. Another portion ofthe cooled LCGO product 132 is condensed in a condenser 806 and sent toa storage. With the presence of heat exchangers 6, an air cooler 804used to cool LCGO product 132 prior to the retrofit is no longer usedexcept, for example, for management of abnormal situations.

Prior to the retrofit, LCGO product 132 was cooled in steam generationsection 700 via one or more heat exchangers 716, 718, 720, 722, 724(FIG. 8) in order to, for example, heat a BFW stream 721 to generate lowpressure steam (LPS) 723; heat a BFW stream 725, contributing to thegeneration of MPS 702; heat a BFW stream 727 received from a naphthaproduct BFW trim cooler and destined for a boiler; or heat a TWA stream729 received from a naphtha product TWA trim cooler and destined for adeaerator. With the presence of heat exchanger 6 to recover waste heatfrom LCGO product 132 in the rundown cooler section, the heat exchangers716, 718, 720, 722, and 724 are no longer used.

Referring again to FIG. 2, lean sponge oil 118 can be withdrawn from alean sponge oil draw-off tray of fractionator 102 and pumped into asponge-oil system 600. Referring to FIG. 7, in sponge-oil system 600,heat exchanger 5 recovers waste heat from lean sponge oil 118, which isused to heat heating fluid sub-stream 22 b. With the presence of heatexchanger 5, an air cooler 604 used to cool lean sponge oil 118 prior tothe retrofit is no longer used except, for example, for management ofabnormal situations. The cooled lean sponge oil 118 flows to the top ofsponge absorber 606, in some cases passing through a heat exchanger 607for further cooling before entering sponge absorber 606. Absorberoverhead 512 from an absorber 502 (FIG. 6, discussed below) is also fedinto sponge absorber 606. Rich sponge oil 136 exits the bottom of spongeabsorber 606, is preheated by exchange with heating fluid stream 38 viaheat exchanger 12, and is returned to a heat transfer tray offractionator 102. With the presence of heat exchanger 12, a heatexchanger 602, which enabled preheating of rich sponge oil 136 byexchange with lean sponge oil 118 prior to the retrofit, is no longerused.

Referring again to FIG. 2, waste heat from overhead 140 fromfractionator 102 is recovered and used to heat heating fluid sub-stream24 a in heat exchanger 1 (in sub-network B). With the presence of heatexchanger 1, an air cooler 142, used to cool overhead 140 prior to theretrofit, is no longer used except, for example, for management ofabnormal situations. The cooled overhead 140 is partially condensed inan overhead condenser 144. The partially condensed overhead 140 flowsinto a fractionator overhead drum 146, such as a reflux drum, wherevapors are separated from condensed hydrocarbon liquid. Vapor 116 exitsoverhead drum 146 and flows under pressure control to the suction of agas compressor 404 (FIG. 5) in a vapor recovery unit. The liquid, whichcan include unstabilized naphtha, is separated into two streams. A firstportion 107 of the liquid is refluxed with the top of fractionator 102and sent along with vapor 116 to the gas compressor 404. A secondportion 108 is pumped to an absorber 502 in the vapor recovery unit 500.Sour water (not shown) is withdrawn from overhead drum 146 and pumped toa treating facility.

Referring to FIG. 4, a retrofit blowdown section 300 of the delayedcoking plant recovers hydrocarbon and steam vapors that are generatedduring quenching and steaming of coke drums 204. Use of blowdown section300 can help to reduce or minimize air pollution generated duringoperation of the delayed coking plant. During cooling of coke drum 204for de-coking processing, steam and wax tailings 208 (FIG. 3) from cokedrum 204 flow to a coker blowdown tower 302 in blowdown section 300.Coke condensate 212 from coke drum 204 flows to a coke condensate drum315 in blowdown section 300, and from coke condensate drum 315 intocoker blowdown tower 302.

In coker blowdown tower 302, steam and wax tailings 208 and cokecondensate 212 are condensed by contact with a cooled circulating oilstream 303. A bottom stream 312 including the wax tailings, diluted bylight gas oil in the circulating oil stream 303, is withdrawn from thebottom of coker blowdown tower 302. A first portion 312 a of bottomstream 312 is cooled by exchange with medium pressure steam 311 (forinstance, from a steam network in the refinery) via a cooler 309. Asecond portion 312 b of bottom stream 312 passes through heat exchanger9, which heats heating fluid sub-stream 26 b with recovered waste heatfrom bottom stream 312 b. The cooled portions 312 a, 312 b of bottomstream 312 are recirculated back to coker blowdown tower 302 as part ofthe circulating oil stream 303. Excess oil can be returned tofractionator 102.

An overhead stream 314 including steam and light hydrocarbons from thetop of coker blowdown tower 302 passes through heat exchanger 8, whichheats heating fluid sub-stream 26 a with recovered waste heat fromoverhead stream 314. Cooled overhead stream 314 exits heat exchanger 8and is condensed in a blowdown condenser (not shown) and fed into ablowdown settling drum 306. In blowdown settling drum 306, oil isseparated from condensate. The oil is pumped to refinery slop. Water 320(for example, sour water) is pumped to treating facilities, such as asour water stripper, or to a decoking-water storage tank for reuse. Avent gas 318 from blowdown settling drum 306, for example, includinglight hydrocarbon vapors, is compressed in a vent-gas compressor (notshown) and separated from the condensed liquid in a vent-gas knockoutdrum (not shown). In some examples, the recovered vent gas 318 flows tofractionator overhead drum 146 (FIG. 2). In some examples, the recoveredvent gas 318 is sent to a fuel gas recovery system. Blowdown 322 fromcoker blowdown tower 302 is quenched and send to coke drums 204 (FIG.3).

In the retrofit blowdown section 300, heat exchangers 8, 9 enable wasteheat to be recovered from the intermittent overhead and bottom streams314, 312, respectively, from coker blowdown tower 302. Heat exchangers8, 9 can operate intermittently. For instance, heat exchanger 8 canoperate for at least about 5 hours per day and the heat exchanger 9 canoperate for at least about 8 hours per day. Prior to the retrofit ofblowdown section, bottom stream 312 and overhead stream 314 were in somecases cooled via air coolers 308, 316, respectively. With the presenceof heat exchangers 8, 9, air coolers 308, 316 are no longer used except,for example, for management of abnormal situations.

Referring to FIGS. 5-7, an overhead gas compression system 400, anabsorber-stripper section 500, and sponge absorber section 600 make upthe vapor recovery unit of the delayed coking plant. The vapor recoveryunit processes vapor 116 and liquid 108 from fractionator overhead drum146. FIGS. 5-7 show retrofits of gas compression system 400,absorber-stripper section 500, and sponge absorber section 600.

Referring to FIG. 5, in the retrofit of overhead gas compression system400, heat exchangers 2, 3 enable waste heat to be recovered fromcompressor inter-stage stream 408 and compressor discharge stream 416,respectively. In overhead gas compression system 400, vapor 116 fromfractionator overhead drum 146 is compressed and cooled by a compressorsuction knockout drum 402 and a coker gas compressor 404. Coker gascompressor 404 is a two-stage compressor with the stages connected by aninter-stage stream 408. Inter-stage stream 408 exits a first stage 404 aof coker gas compressor 404 and passes through heat exchanger 2, whichheats heating fluid sub-stream 24 b with waste heat from inter-stagestream 408. Cooled inter-stage stream 408 is compressed in a compressor412 and fed into a compressor inter-stage drum 414. Inter-stage stream408 flows from compressor inter-stage drum 414 into a second stage 404 bof coker gas compressor 404. A compressor discharge stream 416 exitingfrom the second stage 404 b of coker gas compressor 404 passes throughheat exchanger 3, which heats heating fluid sub-stream 24 c with wasteheat from compressor discharge stream 416. Cooled compressor dischargestream 416 is compressed in a compressor 420 and fed into an absorberstripper feed drum 406. From absorber stripper feed drum 406, a vaporstream 506 is fed into the bottom of an absorber 502 (FIG. 6) and aliquid stream 508 is pumped into the top of a stripper 504.

Prior to the retrofit of overhead gas compression system 400,inter-stage stream 408 and compressor discharge stream 416 were in somecases cooled via air coolers 410, 418, respectively. With the presenceof heat exchangers 2, 3, air coolers 410, 418 are no longer used except,for example, for management of abnormal situations.

Referring to FIG. 6, in the retrofit of absorber-stripper section 500,heat exchanger 4 enables waste heat to be recovered from the stabilizednaphtha stream 612 from the bottom of the debutanizer 605 (FIG. 7).Liquid 108, such as unstabilized naphtha, from fractionator overheaddrum 146 flows directly into the top of an absorber 502. Absorber 502and a stripper 504 produce a bottoms stream 510 that contains most ofthe C3 and heavier material in the feed processed by absorber 502 andstripper 504. An overhead 512 from absorber 502 contains the C2 andlighter material in the feed, along with some unrecovered C3 and heaviermaterial. Overhead 509 from stripper 504 and bottoms 505 from absorber502 are returned to absorber stripper feed drum 406 (FIG. 5).

Referring also to FIG. 7, overhead 512 from absorber 502 is fed into asponge absorber 606, where unrecovered C3 and heavier material isrecovered and recycled back to fractionator 102 as rich sponge oil 136.The C2 and lighter material in overhead 512 exits through the top ofsponge absorber 606 as an overhead 530 and is processed by a treatingsection for removal of compounds such as hydrogen sulfide, mercaptans,or other sulfur compounds, as described in more detail below. In someexamples, sponge absorber 606 can use a side cut from fractionator 102as an absorbing medium.

Bottoms stream 510 from stripper 504 is pumped to a debutanizer 605,which removes C3 and C4 as an overhead distillate 608 and leavesstabilized naphtha 612 as a bottoms product. Stabilized naphtha 612 canbe sent to storage or can be further processed. For instance, referringagain to FIG. 6, which shows a retrofit of an absorber-stripper section500, stabilized naphtha 612 can pass through heat exchanger 4, whichheats heating fluid sub-stream 22 a with recovered waste heat fromstabilized naphtha stream 612. The cooled stabilized naphtha 612 exitingheat exchanger 4 is compressed in a compressor 524 and joined withliquid 108 from fractionator overhead drum 146 to be fed into the top ofabsorber 502. Heat exchanger 11 uses the heat from heating fluid stream38 to heat up or vaporize stripper bottom product 514.

Prior to the retrofit of absorber stripper section 500, stabilizednaphtha 612 was used to re-boil stripper bottom product 514 via a heatexchanger 516, cooled by exchanged with boiler feed water (BFW) 528 viaa heat exchanger 518, cooled by exchange with tempered water (TWA) 532via a heat exchanger 520, and cooled in an air cooler 522. With thepresence of heat exchanger 4, heat exchangers 516, 518, 520, and aircooler 522 are no longer used except, for example, for management ofabnormal situations. In addition, prior to the retrofit of absorberstripper section 500, stripper bottom product 514 was re-boiled withmedium pressure steam (MPS) re-boiler 526, which is no longer used withthe presence of heat exchanger 11.

Referring again to FIG. 7, overhead distillate 608 from debutanizer 605,which can be, for example, C3-C4 liquefied petroleum gas (LPG), goes toa treating section for removal of compounds such as hydrogen sulfide,mercaptans, or other sulfur compounds. The treating section can includeone or more condensers, a coker product gas scrubber 610, a sour gasknockout drum, an amine absorber (such as a liquid-liquid contactor 616,for instance, a C3-C4 amine contactor), an amine knockout drum 630, anda settling drum 632 (for instance, a C3-C4 amine settling drum), and canmake use of lean diethanolamine 640 received from an amine regenerationunit. Outputs from the treating section are sent to variousdestinations. Fuel gas 634 output as an overhead stream from amineknockout drum 630 is sent to heaters, a fuel gas knockout drum, and afuel gas header. C3/C4 product 636 from settling drum 632 is sent to anLPG mercaptan oxidation (merox) unit. Rich DEA 638 from the bottom ofcoker product gas scrubber 610 is processed in an amine regenerationunit.

In some examples, one or more of the heat exchangers added in theretrofit of the delayed coking plant can be implemented with a thermalduty less than that shown in the figures. A subsequent, second retrofitcan be conducted to increase the thermal duty of one or more of the heatexchangers, for example, by adding surface area or heat transferenhancements to heat exchangers. In some examples, air coolers that areshown as no longer used in the retrofit can be used if one or more ofthe heat exchangers has a thermal duty less than that shown in thefigures.

Referring to FIG. 10, in a decoking operation, a full coke drum (forexample, coke drum 204 b in FIG. 2) is steamed out to remove anyresidual-oil liquid (900). The resulting mixture of steam andhydrocarbon is sent first to fractionator 102 as a stream of overheadvapors 206 and later to coker blowdown section 300, where wax tailings208 are recovered. The coke drum is filled with water, allowing the drumto cool below 93° C. (902). The steam generated during cooling of thecoke drum is condensed in coker blowdown section 300. The cooling wateris drained from the coke drum and recovered for reuse (904).

The top and bottom heads of the coke drum are removed in preparation forcoke removal (906), and the coke drum is decoked (908). In someexamples, the coke drum is decoked via hydraulic decoking, in whichhigh-pressure water jets are used to cut the coke from the coke drum.The water is separated from the coke fines and reused.

The top and bottom heads of the coke drum are replaced and the coke drumis tightened, purged, and pressure-tested (910). Steam and vapors fromthe hot coke drum (for example, coke drum 204 a) are used to heat up thecold, decoked coke drum (912). Condensed water is sent to coker blowdowntower 302 and condensed hydrocarbons are sent to either fractionator 102(as feed 206) or coker blowdown tower 302 (as wax tailings 208). Theheated, decoked coke drum is placed online to receive the feed stream(914) and the decoking cycle is repeated for the other coke drum. Insome examples, a 36-hour coking cycle can be used in which each drum iscoked for 18 hours and decoked for 18 hours. In some examples, a shortercoking cycle can be used, such as 11 hours, 14 hours, or 16 hours.Shorter coking cycles can enable increased unit throughput by fillingthe coke drums 204 more quickly.

Coke that has not yet been calcined for removal of excess moisture andvolatile matter is referred to as “green” coke. Green coke can becalcined in a variety of ways, such as a rotary-kiln method or arotary-hearth method. In the rotary-kiln method, after draining, thecoke is charged to a crusher and then to one or more kiln feed bins. Therate of charge to the kiln is controlled by a continuous-weigh feeder.In the kiln, the residual moisture and the volatile matter are removedas the green coke moves counter to the heat flow. Process heat issupplied to the kiln through a burner. Another source of process heat iscombustion of the volatile matter released by the green coke in thekiln. The calcined coke leaving the kiln is discharged into a rotarycooler, where the coke is quenched with direct water sprays or streamsof ambient air. The calcined, cooled coke is conveyed from the rotarycooler to storage.

FIGS. 11-17 show details of a grassroots delayed coking plant thatincludes the heat exchangers of combined heat and power system 10.

FIG. 11 shows a grassroots fractionation section 180. A heat exchanger13 enables heat exchange between feed stream 210 (to be heated) and HCGOpumparound stream 90 (to be cooled). HCGO pumparound stream 90 flowsthrough heat exchanger 13, through heat exchanger 107, and then directlyto heat exchanger 618 (FIG. 17) for re-boiling of the debutanizerbottom.

Referring also to FIG. 12, heating feed stream 210 with waste heat fromHCGO pumparound stream 90 enables feed stream 210 to enter coker heater202 at a high temperature, thus enabling fuel savings in coker heater202.

Referring again to FIG. 11, in grassroots fractionation section 180,overhead 140 from fractionator 102 is cooled via exchange with heatingfluid sub-stream 24 a by heat exchanger 1 (in sub-network B). Waste heatfrom overhead 140 is used to heat heating fluid sub-stream 24 a, andheated fluid sub-stream 24 a is combined into heating fluid header 28 ofsub-network B 70.

Referring to FIG. 13, in a grassroots blowdown section 380, heatexchangers 8, 9 enable waste heat to be recovered from the intermittentoverhead and bottom streams 314, 312, respectively, from coker blowdowntower 302. Heat exchanger 8 heats heating fluid sub-stream 26 a withwaste heat from overhead stream 314 and heat exchanger 9 heats heatingfluid sub-stream 26 b with waste heat from bottom stream 312. The twoheating fluid sub-streams 26 a, 26 b are combined into intermittentheader 32 of sub-network C 80, which flows into thermal storage tank 34.Heat exchangers 8, 9 operate intermittently. For instance, heatexchanger 8 can operate for at least about 5 hours per day and the heatexchanger 9 can operate for at least about 8 hours per day.

Referring to FIG. 14, in a grassroots overhead gas compression system480, heat exchangers 2, 3 enable waste heat to be recovered fromcompressor inter-stage stream 408 and compressor discharge stream 416,respectively. Heat exchanger 2 heats heating fluid sub-stream 24 b withwaste heat from compressor inter-stage stream 408 and heat exchanger 3heats heating fluid sub-stream 24 c with waste heat from compressordischarge stream 416. Heated fluid sub-streams 24 b, 24 c are combinedinto heating fluid header 28 of sub-network B 70.

Referring to FIG. 15, in a grassroots absorber-stripper section 580,heat exchanger 4 enables waste heat to be recovered from the stabilizednaphtha stream 612 from the bottom of the debutanizer 605 (FIG. 16).Heat exchanger 4 heats heating fluid sub-stream 22 a with waste heatfrom stabilized naphtha stream 612 and heated fluid sub-stream 22 a iscombined into heating fluid header 30 of sub-network A 60. Heatexchanger 11 uses the heat from heating fluid stream 38 to re-boilstripper bottom product 514.

Referring to FIG. 16, in a grassroots sponge absorber section 680, heatexchanger 5 enables waste heat to be recovered from lean sponge oilstream 118. Heat exchanger 5 heats heating fluid sub-stream 22 b withwaste heat from lean sponge oil stream 118 and heated fluid sub-stream22 b is combined into heating fluid header of sub-network A 60. Heatexchanger 12 uses the heat from heating fluid stream 38 to heat up richsponge oil stream 136.

Referring to FIG. 17, in a grassroots rundown cooler section 880, heatexchangers 6, 7 enable waste heat to be recovered from LCGO product 132and HCGO product 704, respectively. Heat exchanger 6 heats heating fluidsub-stream 22 c with waste heat from LCGO product 132 and heat exchanger7 heats heating fluid sub-stream 22 d with waste heat from HCGO product704. Heated fluid sub-streams 22 c, 22 d are combined into heating fluidheader of sub-network A 60. HCGO product 704 going to storage is furthercooled, if necessary, by a water cooler 730. HCGO product 706 going tothe seal oil filter is cooled by a heat exchanger 732, for example, byexchange with boiler feed water.

Other implementations are also within the scope of the following claims.

What is claimed is:
 1. A system comprising: a heat exchange system comprising: a first heat exchanger configured to heat a first fluid stream with heat recovered from a first heat source in a delayed coking plant thereby producing a heated first fluid stream; a second heat exchanger configured to heat a second fluid stream with heat recovered from a second heat source in the delayed coking plant thereby producing a heated second fluid stream, wherein the heated second fluid stream has a lower temperature and a greater quantity of heat than the heated first fluid stream; a third heat exchanger configured to heat a plant stream in the delayed coking plant by exchange with a third fluid stream thereby producing a heated third fluid stream, wherein the third fluid stream includes the heated first fluid stream and a hot fluid stream; and a power generation system configured to generate power using heat from the heated second fluid stream and the heated third fluid stream.
 2. The system of claim 1, further comprising a fluid storage tank configured to receive a fourth stream of hot fluid and to output the hot fluid stream.
 3. The system of claim 2, wherein the fourth stream is an intermittent stream and wherein the fluid storage tank is configured to pass the hot fluid stream continuously.
 4. The system of claim 2, further comprising a fourth heat exchanger configured to heat a fourth fluid stream from the delayed coking plant to produce the fourth stream of hot fluid.
 5. The system of claim 4, wherein the fourth hot stream has a greater quantity of heat and a lower temperature than the heated first fluid stream.
 6. The system of claim 4, wherein the fourth heat exchanger recovers heat from an output stream from a coker blowdown tower in the delayed coking plant.
 7. The system of claim 4, wherein the heat exchange system comprises multiple fourth heat exchangers each configured to heat a portion of the fourth fluid stream, wherein each fourth heat exchanger recovers heat from a corresponding intermittent heat source in the delayed coking plant.
 8. The system of claim 1, wherein the first heat exchanger recovers heat from a bottom stream from a debutanizer in the delayed coking plant.
 9. The system of claim 1, wherein the first heat exchanger recovers heat from a stream output from a fractionator in the delayed coking plant.
 10. The system of claim 1, wherein the heat exchange system comprises multiple first heat exchangers each configured to heat a portion of the first fluid stream, wherein each first heat exchanger recovers heat from a corresponding first heat source in the delayed coking plant.
 11. The system of claim 1, wherein the second heat exchanger recovers heat from an overhead stream from a fractionator in the delayed coking plant.
 12. The system of claim 1, wherein the second heat exchanger recovers heat from an inter-stage stream or a discharge stream of a coker gas compressor in the delayed coking plant.
 13. The system of claim 1, wherein the heat exchange system comprises multiple second heat exchangers each configured to heat a portion of the second fluid stream, wherein each second heat exchanger recovers heat from a corresponding second heat source in the delayed coking plant.
 14. The system of claim 1, wherein the temperature of the heated third fluid stream is less than the temperature of the third fluid stream.
 15. The system of claim 1, wherein the third heat exchanger is configured to heat a stripper bottom product from a stripper in the delayed coking plant by exchange with the third fluid stream.
 16. The system of claim 1, wherein the third heat exchanger is configured to heat a rich sponge oil stream from a sponge absorber in the delayed coking plant by exchange with the third fluid stream.
 17. The system of claim 1, wherein the heat exchange system comprises multiple third heat exchangers each configured to heat a corresponding stream in the delayed coking plant by exchange with a portion of the third fluid stream.
 18. The system of claim 1, wherein the power generation system comprises an Organic Rankine cycle system.
 19. The system of claim 1, wherein the system is integrated into the delayed coking plant as a retrofit to the delayed coking plant. 